Downhole formation fluid (oil and gas) leakage may occur through production tubing, casing, or annular cement sheath in between the casing and formation. Such a fluid leakage may become problematic when either water transports to a production zone or a rich quality production zone communicates with a poor quality production zone through the flow channel created by the leak. If fluid constrained within an annulus becomes pressurized, such as from a leak or thermal expansion, a pressure differential may overstress and/or rupture a casing or tubing wall. The phenomenon of trapped annulus pressure or annular pressure buildup is traditionally addressed by overdesigning casing strings and production tubing, with a concomitant cost penalty. Further, if the leak allows fluid flow between different zones, it may cause a temperature deviation from expected values in addition to the cross-contamination mentioned above. A formation fluid leak may induce dynamic pressure variation throughout the formation, casing, cementing annulus, and production tube.
Identification and accurate location of a downhole fluid leak event is challenging. Identification of a leak event may rely on measuring downhole acoustic or ultrasonic noise, using geophones or hydrophones, for example, with concomitant sampling, recording, and analysis of large volumes of digital data. Conventional leak detection logging tools may continuously sample acoustic data on many channels at high sample rates simultaneously. The vast quantity of sampled data form a fast data stream, which may invariably result in a low duty cycle. That is, conventional leak detection logging tools may only collect data during a low percentage of logging time while spending the remaining time saving the collected data to a large memory bank. Of all the collected acoustic data, only a small portion is typically used.